1. Field of the Invention
The present invention relates generally to methods for predicting hydrocarbon production from a subterranean formation using reflection seismic data. In another aspect, the invention concerns a method of predicting hydrocarbon production from a subterranean formation based upon reservoir quality values and seismic coherence factors determined from reflection seismic data.
2. Description of the Prior Art
For many years seismic exploration for oil and gas has involved the use of a source of seismic energy and its reception by an array of seismic detectors, generally referred to as geophones. When used on land, the source of seismic energy can be a high explosive charge electrically detonated in a borehole located at a selected point on a terrain, or another energy source having capacity for delivering a series of impacts or mechanical vibrations to the earths surface. Offshore, air gun sources and hydrophone receivers are commonly used. The acoustic waves generated in the earth by these sources are transmitted back from strata boundaries and/or other discontinuities and reach the earth's surface at varying intervals of time, depending on the distance traversed and the characteristics of the subsurface traversed. On land these returning waves are detected by the geophones, which function to transduce such acoustic waves into representative electrical analog signals, which are generally referred to as traces. In use on land, an array of geophones is laid out along a grid covering an area of interest to form a group of spaced apart observation stations within a desired locality to enable construction of three dimensional (3D) views of reflector positions over wide areas. The source, which is offset a desired distance from the geophones, injects acoustic signals into the earth, and the detected signals at each geophone in the array are recorded for later processing using digital computers, where the analog data is generally quantized as digital sample points, e.g., one sample every two milliseconds, such that each sample point may be operated on individually. Accordingly, continuously recorded seismic field traces are reduced to vertical cross sections, or volume representations, or horizontal map views which approximate subsurface structure. The geophone array is then moved along to a new position and the process is repeated to provide a seismic survey. A 3D seismic survey is data gathered at the surface and presented as a volume representation of a portion of the subsurface.
After exploration of an area is completed, data relating to energy detected at a plurality of geophones will have been recorded, where the geophones are located at varying distances from the shotpoint. The data is then reorganized to collect traces from data transmitted at various shotpoints and recorded at various geophone locations, where the traces are grouped such that the reflections can be assumed to have been reflected from a particular point within the earth (i.e., a common midpoint). The individual records or “traces” are then corrected for the differing distance the seismic energy travels through the earth from the corresponding shotpoints, to the common midpoint, and upwardly to the various geophones. This step includes correction for the varying velocities through rock layers of different types and changes in the source and receiver depths. The correction for the varying spacing of shotpoint/geophone pairs is referred to as “normal move out.” After this is done the group of signals from the various midpoints are summed. Because the seismic signals are of a sinusoidal nature, the summation process serves to reduce noise in the seismic record, and thus increasing its signal-to-noise ratio. This process is referred to as the “stacking ” of common midpoint data, and is well known to those skilled in the art. Accordingly, seismic field data undergoes the above-mentioned corrections, and may also undergo migration, which is an operation on uninterpreted data and involves rearranging of seismic information so that dipping horizons are plotted in their true location. Other more exotic known processing techniques may also be applied, which for example enhance display of faults, stratigraphic features, amplitude versus offset (AVO) or some attribute such as peak amplitude, instantaneous frequency or phase, polarity etc., before the continuously recorded traces are reduced to vertical or horizontal cross sections or horizontal map views.
It is generally known that certain seismic attributes (e.g., seismic amplitude) of seismic data generated from a reflection seismic survey can approximate reservoir quality (e.g., thickness, porosity, saturation, or net pore feet). It is also known that initial hydrocarbon flow from a well is typically controlled by reservoir quality. However, many wells that exhibit high levels of initial production quickly taper off due to lack of geologic connectivity around the well. Wells with high geologic connectivity have the potential to produce at relatively steady rates for long periods of time. Thus, total well production at a certain location can be estimated by looking at both reservoir quality and geologic connectivity. It is known that seismic coherence is an indicator of geologic connectivity, and that hydrocarbon flow paths tend to follow common geology. Thus, reflection seismic data can provide an indication of both reservoir quality (initial flow) and geologic connectivity (sustained flow).
Although a number of techniques for determining trace-to-trace coherence factors (which indicate geologic connectivity) are known in the art, conventional seismic coherence determination methods only compare each trace to a fixed geometry of its neighboring traces. Thus, the trace-to-trace coherence values only provide an indication of very localized geologic connectivity between adjacent traces. In reality, however, oil and natural gas can flow from as much as 3,000 or 5,000 feet away from a well. Thus, conventional seismic coherence methods do not provide an accurate indication of the geologic connectivity of an entire field.